Venture Global Inc

Overview

Our Company

Venture Global is a long-term, low-cost provider of U.S. LNG sourced from resource rich North American natural gas basins. Venture Global’s business includes assets across the LNG supply chain, including LNG production, natural gas transport, shipping and regasification. We have fundamentally reshaped the development and construction of LNG production, establishing us as a rapidly growing company delivering critical LNG to the world. Our innovative and disruptive approach, which is both scalable and repeatable, allows us to bring LNG to a global market years faster and at a lower cost. We believe supplying this clean, affordable fuel promotes global energy security and is essential to meeting growing global demand.

Natural gas is one of the most important resources worldwide and is required to generate reliable electricity that underpins economic development and drives industry. Once natural gas is supercooled to -260°F, it converts to liquid form and reduces to 1/600th of its original volume, enabling large quantities of natural gas to be loaded and shipped by LNG tankers. The resulting LNG can be transported to international markets that lack domestic supply, displacing more carbon intensive sources of energy such as coal, diesel, and heavy fuel oil, and serving as an integral part of a cleaner energy future. We believe our business model has demonstrated that in a competitive commodity market, lower cost and overall faster delivery wins market share. Our approach capitalizes on both of these advantages, supporting significant additional growth opportunities.

Our Liquefaction and Export Projects

We are commissioning, constructing, and developing five natural gas liquefaction and export projects near the U.S. Gulf Coast in Louisiana, utilizing our unique “design one, build many” approach. Each project is designed or is being developed to include an LNG facility and associated pipeline systems that interconnect with several interstate and intrastate pipelines to enable the delivery of natural gas into the LNG facility.

Below is a geographic overview of our five current projects, which is followed by a detailed description of each project.

As illustrated by the chart below, our five current projects are being designed to deliver a total expected peak production capacity of 143.8 mtpa, which consists of an aggregate of 104.4 mtpa expected nameplate capacity and an aggregate of 39.4 mtpa of expected excess capacity. These amounts do not account for any potential bolt-on expansion liquefaction capacity. The expected nameplate capacity of our facilities measures the minimum operating performance thresholds guaranteed by the equipment providers, and the expected excess capacity represents the additional LNG that we aim to produce above such guaranteed amounts. Although COD has not yet occurred under the post-COD SPAs for any of our projects, we have been generating proceeds from the sale of commissioning cargos at the Calcasieu Project since the first quarter of 2022 and at the Plaquemines Project since January 2025, and expect to do so at each of our other projects during commissioning prior to achieving COD for the relevant project or phase of a project.

(1) Targets based on, among other things, anticipated timeframes for the receipt of certain regulatory approvals as described in—Governmental Regulation of this Form 10-K.

(2) Anticipated based on capacity, scale, location and infrastructure. Subject to regulatory review and approval, among other things, and may change based on design considerations, engagement with contractors, and other factors.

Venture Global seeks to own all or substantially all of the equity ownership in its current five LNG projects and any future projects. As of the date of this Form 10-K, we own 100% of the common equity interests in all of our natural gas liquefaction and export projects. Upon COD for the Calcasieu Project, we expect our ownership of the common equity interests in the Calcasieu Project to be reduced to approximately 77% (assuming that we service all future distributions on the Holdings Preferred Units until the commencement of COD in cash), after adjusting for the automatic conversion of the convertible preferred units in Calcasieu Holdings held by an outside equity investor. We believe that our significant ownership stake in our projects provides us with full managerial control, facilitating nimble decision-making and speed of execution.

Optimization and Bolt-on Expansion Opportunities

Our projects also offer potential optimization, increased capacity and expansion opportunities. In particular, our projects are sited and designed with the intention of allowing for bolt-on expansions, incorporating laydown area, redundancies across the facility infrastructure and our mid-scale factory-fabricated liquefaction trains. Subject to receiving the requisite regulatory approvals, we intend to pursue the development of these expansion opportunities beyond our current combined expected peak production capacity of 143.8 mtpa. Any incremental equipment would benefit from pre-existing plant facilities and related infrastructure (such as marine offloading facilities, LNG storage tanks and perimeter walls), although may require, among other things, incremental natural gas supply arrangements, pipelines, and pipeline transportation capacity, for the applicable project in order to support the additional capacity. We aim to place up to an aggregate of approximately 49.5 mtpa of additional bolt-on expansion liquefaction capacity of incremental modular mid-scale liquefaction trains at most of our current projects. In particular, on March 6, 2025, we submitted to FERC a request to initiate the pre-filing process for additional facilities for a Plaquemines Project bolt-on expansion consisting of approximately 18.6 mtpa of incremental peak production capacity.

Our Project Development and Construction Approach

Our project development and construction approach utilizes proven liquefaction system technology and equipment in a unique mid-scale, factory-fabricated configuration that we developed. Instead of two or three large, complex liquefaction trains, the Calcasieu Project and the Plaquemines Project utilize 18 and 36 mid-scale factory-fabricated liquefaction trains, respectively. We expect to use the same approach and technology at the CP2 Project, the CP3 Project and the Delta Project. Our modules are built and assembled off-site at manufacturing and fabrication facilities in Italy and then shipped to our project sites fully-assembled and packaged for installation, allowing onsite work to progress in parallel. We believe our innovative configuration, long-term equipment contracting strategy and hands-on project management approach significantly reduces construction and installation costs, as well as construction time and schedule risk, thereby allowing us to be more cost-competitive in the LNG market while also producing substantial amounts of commissioning cargos and related cash proceeds. For example, our initial two projects, the Calcasieu Project and the Plaquemines Project, in each case, began producing LNG approximately two and a half years after the relevant final investment decision, while significant construction work remained ongoing.

While traditional LNG projects often rely on bespoke designs and configurations, our approach, leveraging factory-fabricated equipment manufactured with our “design one, build many” method, allows us to apply the lessons we learn at each project to our subsequent projects, with the goal of continuously improving our execution, accelerating construction timelines, reducing costs, and expanding production. We believe we will continue to benefit from this virtuous cycle as we grow.

Gas Supply and Transportation

We have entered into a portfolio of natural gas supply agreements with domestic natural gas suppliers to furnish feed gas to the Calcasieu Project and the Plaquemines Project for liquefaction and power generation. We have also entered into multiple transport capacity agreements with interstate pipeline companies to provide natural gas transportation to the Calcasieu Project and the Plaquemines Project via short-run lateral pipelines. The CP2 Project has entered into agreements for substantial firm transportation capacity with third parties and CP Express.

LNG Sales – Commissioning

By design, conventional, stick-built projects generally only engage in several months of commissioning production, thereby limiting the number of cargos produced before full commercial operations occur. Due to our unique modular development approach and configuration consisting of many mid-scale liquefaction trains, which are delivered and installed sequentially, it is necessary to commission and test our LNG facilities sequentially over a longer period of time than traditional LNG facilities with substantially fewer, larger-scale liquefaction trains. The commissioning of the liquefaction trains at our facilities begins while portions of our facilities remain under construction.

This important reliability and technical requirement results in earlier production of LNG than with traditional LNG facilities. We believe this earlier production of LNG positions us to produce a substantial number of commissioning cargos for each of our LNG projects, generating proceeds that may be used to support any remaining construction work or fund subsequent projects and future growth. As an example of this, on March 1, 2022, we announced the successful loading and departure of our first cargo of LNG from the Calcasieu Project, just over two and a half years from our final investment decision for the Calcasieu Project. Similarly, on December 26, 2024, we announced the successful loading and departure of our first cargo of LNG from the Plaquemines Project, just over two and a half years from our final investment decision for Phase 1 of the Plaquemines Project.

LNG commissioning cargos are sold to various customers under master SPAs, either as single cargos or as strips of multiple cargos to be loaded over a period of time, and are based on spot and/or forward prices, generally consisting of a liquefaction fee and a variable commodity charge, at the time of execution. As a result, the amount of revenue we are able to generate from such sales of commissioning cargos has differed, and will likely continue to differ, from period to period and from project to project, and such differences could be material.

LNG Sales – Post-COD SPAs

The project companies for the Calcasieu Project, the Plaquemines Project and the CP2 Project have signed LNG sales and purchase agreements, or SPAs, to sell LNG based on a predetermined pricing formula that commences after we achieve the commercial operation date, or COD, of the relevant project or phase thereof. Under our post-COD SPAs, customers will purchase LNG from us for a price consisting of a fixed facility charge (a portion of which is subject to an annual adjustment for inflation) per MMBtu of LNG, plus a variable commodity charge equal to at least 115% of Henry Hub per MMBtu of LNG. In certain circumstances, customers may elect to cancel or suspend deliveries of LNG cargos, but they will still be required to pay the fixed fee (but not the variable commodity charge) with respect to contracted volumes that are not delivered as a result of such cancellation or suspension. Under each such post-COD SPA, COD does not occur unless the applicable project company has notified such customer that (i) all of the project’s facilities have been completed and commissioned, including any ramp up period, and (ii) the project is capable of delivering LNG in sufficient quantities and necessary quality to perform all of its obligations under such post-COD SPA.

As of December 31, 2024, we have executed 39.25 mtpa of such post-COD SPAs with a well recognized set of third party customers that we believe constitute one of the strongest portfolios of institutional LNG buyer credits in the world. Approximately 95% of our contracted post-COD SPAs – or 37.45 mtpa of such 39.25 mtpa – are 20-year fixed price agreements, providing a long-term stream of contracted cash flow. We have also executed 1.8 mtpa of post-COD SPAs on a short- and medium-term basis and we plan to continue to optimize our portfolio, balancing profit, duration, and risk.

Our third-party post-COD SPAs as of December 31, 2024 represent expected total contracted revenue of approximately $107 billion over the life of such SPAs. Our total contracted revenue is illustrative only and is based on a number of important assumptions. See Item 1A.—Risk Factors—Risks Relating to Our Business—Total contracted revenue is based on certain assumptions and is presented for illustrative purposes only and actual sales under our SPAs may differ materially from such illustrative operating results of this Form 10-K. The weighted average life of all of our post-COD SPAs is approximately 19 years.

Excess Capacity

LNG projects are typically able to achieve production beyond their guaranteed nameplate capacities. For many traditional large international stick-built projects, generating additional production capacity generally requires substantial incremental equipment and construction, with associated injections of capital. By comparison, we believe our projects will have the potential to produce materially beyond their nameplate capacities, with modest incremental capital investment because of our modular design as well as redundancy features inherent in our project design.

We aim to construct and maintain LNG facilities that are capable, in most cases, of producing excess capacity of at least 30% of their guaranteed nameplate capacity, which provides the potential for additional cash proceeds from our projects. Any such excess capacity will generally be available to us to sell on a short-, medium-, or long-term basis, providing flexibility to optimize pricing.

With respect to the Calcasieu Project, our inaugural project, we expect to produce excess capacity of slightly less than 30% of its nameplate capacity and we have received FERC approval for a maximum production capacity of 12.4 mtpa. With respect to the Calcasieu Project, any excess capacity above the nameplate capacity of 10.0 mtpa will be sold to VG Commodities under an Intercompany Excess Capacity SPA. We have contracted to resell a portion of the Calcasieu Project excess capacity that is sold to VG Commodities to a third-party pursuant to a long-term SPA. With respect to the Plaquemines Project, any excess capacity above the nameplate capacity of 13.3 mtpa for Phase 1 or above the nameplate capacity of 6.7 mtpa for Phase 2 will be sold to VG Commodities under the applicable Intercompany Excess Capacity SPA (one per phase). LNG sold under such Intercompany Excess Capacity SPAs can, to the extent not previously committed to third parties, be resold to third party customers at our discretion under short-, medium- or long-term contracts, providing the flexibility to optimize pricing and capture additional revenue on an ongoing basis after COD for each of Phase 1 and Phase 2, at price levels that we expect will typically exceed the fixed fee prices secured under the Plaquemines Foundation SPAs. We expect to enter into similar Intercompany Excess Capacity SPAs for our other projects under development.

Our Complementary Assets

Pipeline Projects

We are in the advanced stages of development to establish complementary gas transportation for our development projects. As an example, we have partnered with WhiteWater Midstream, LLC, a Texas-based pipeline developer and operator, to jointly develop, permit, and site the approximately 190 mile Blackfin pipeline project, a long-haul 48-inch intrastate pipeline designed to facilitate the transportation of Permian sourced gas from the Matterhorn Express pipeline to certain interconnecting pipelines, including the CP Express Pipeline.

Shipping

In order to vertically integrate our business and expand our customer base to premium markets that have no or limited LNG transportation resources, we have contracted to acquire newbuild LNG tankers and have also chartered additional LNG tankers on a medium- and short-term basis. As of December 31, 2024, we have contracted to acquire nine LNG tankers, constructed by two of the premier shipbuilders in South Korea, of which two LNG tankers have already been delivered. The remaining LNG tankers are under construction and are scheduled to be delivered on a rolling basis through 2026.

We have also executed two medium-term and two short-term charters for additional LNG tankers, which were delivered in the second half of 2024, bringing our total shipping portfolio to a total of thirteen LNG tankers. We believe these LNG tankers will support our ability to optimize LNG marketing and sales and differentiate us from many other LNG exporters in North America.

LNG Regasification Capacity

We are pursuing opportunities to secure LNG regasification capacity in key import markets to support current and prospective customers and differentiate ourselves from other LNG exporters in North America. As part of this initiative, through our wholly-owned subsidiary, VG LNG Marketing, LLC, we have acquired firm regasification facility capacity at the largest LNG regasification terminal in Europe, Grain LNG in the United Kingdom. We have contracted to import 42 LNG cargos per year from approximately 2029 until 2045 (apart from a limited period).

Additionally, we have secured approximately 1 mtpa of LNG regasification capacity at the new Alexandroupolis LNG receiving terminal in Greece for five years, which is expected to begin in October 2025. Our capacity accounts for approximately 25% of the total terminal capacity at Alexandroupolis, or approximately 12 LNG cargos annually.

We believe these contracted capacities will allow us to supply LNG and regasified natural gas directly into the European market to current and additional downstream customers.

Carbon Capture and Sequestration Initiative

In May 2021, we announced plans for carbon capture and sequestration, or CCS, facilities at or near the Calcasieu Project and Plaquemines Project sites that will be designed to compress CO2 emissions from these projects and subsequently inject it into subsurface saline aquifers near the project sites, where it would be permanently stored. We plan to implement or utilize such CCS facilities at our other projects as well, such as the CP2 Project, the CP3 Project and the Delta Project, which are located nearby the Calcasieu Project and Plaquemines Project. We have conducted extensive studies to confirm the feasibility of the CCS facilities and have leased approximately 27,000 acres of pore space with the State of Louisiana. In July 2023, we submitted an application to the U.S. EPA for a Class VI well permit in respect of the Calcasieu Project and CP2 Project. We are in the process of completing the remaining applications for regulatory approval in respect of our current projects.

Our Liquefaction and Export Projects

(1) Potential bolt-on expansion opportunity based on facility capacity, scale, location and infrastructure. Subject to regulatory approval, among other things, and may change based on design considerations, regulatory review process, engagement with contractors and other factors.

(2) Cumulative exports to FTA Nations and Non-FTA Nations cannot exceed the permitted capacity as authorized by the FERC.

(3) Our request to increase the authorized level of exports to Non-FTA Nations from 12.0 mtpa to 12.4 mtpa is still pending. See—Governmental Regulation—DOE Export Authorizations—Calcasieu Project.

Project Construction and Commissioning

Construction of the Calcasieu Project is substantially complete and the project is currently undergoing a multi-faceted commissioning program to complete the facility’s components, bring them to design specification and establish reliable and safe facility-wide operating conditions and to prepare for the commencement of lender-required performance reliability testing. Significant work related to commissioning, carryover completions, and rectification is ongoing and includes remedying unexpected challenges with equipment reliability identified during the first-time implementation of our innovative design and configuration, and reliability testing. We believe such work will need to be completed before certain components operate as intended and the facility can be fully commercially operable, and COD can occur. As of the date of this Form 10-K, we have completed substantial remediation work on the heat recovery steam generators, or HRSGs, of the power island system that was necessitated by the manufacturer of such equipment, General Electric, having implemented a change in method of fabrication that led to substantial leaking that was identified during commissioning tests. As of December 31, 2024, among the other ongoing rectification work, our gas pre-treatment units underperformed and were not able to pass their required performance tests. In January 2025 and February 2025, pre-treatment units "A" and "C" passed their required performance tests, respectively, though we are validating the test results for unit “C” with the independent engineer appointed by the lenders under the Calcasieu Pass Credit Facilities. We continue to engage in remediation efforts with UOP, the manufacturer, to improve pre-treatment unit "B" so that it will achieve the designed levels of performance and redundancy and pass its required performance tests.

We are targeting to complete all remediation work and achieve COD on April 15, 2025, after the project has completed its commissioning process and testing and is capable of safely and reliably producing its designed nameplate levels of LNG volumes.

As of December 31, 2024, the Calcasieu Project executed approximately 25.2 million work hours with a TRIR of 0.10. This safety performance far exceeds the national average for the industry of 1.9 for 2023.

Commissioning LNG Sales

Due to our unique project configuration (which includes many mid-scale liquefaction trains, which are delivered and installed sequentially) and development approach, it is necessary to commission and test our LNG facilities sequentially over a longer period of time than traditional LNG facilities with substantially fewer, larger-size liquefaction trains. This important reliability and technical requirement has resulted in the production of LNG starting earlier in the construction schedule than at traditional LNG facilities, and in far greater quantities – requiring us to produce a substantial number of commissioning cargos at the Calcasieu Project. Despite the longer than expected commissioning process at the Calcasieu Project due to certain unexpected challenges with equipment reliability that we are in the process of remediating, during the year ended December 31, 2024, the Calcasieu Project exported 140 LNG commissioning cargos. Pursuant to our project financing arrangements, a portion of the proceeds from the sale of these LNG commissioning cargos is held in cash reserve accounts in an amount we expect to be necessary to complete the project and achieve COD under the Calcasieu Foundation SPAs. As of December 31, 2024, we had an aggregate of $395 million of cash in reserve accounts at the Calcasieu Project, of which approximately $226 million is reserved for debt service.

(1) Approximately 85% of the Calcasieu Project's expected 10.0 mtpa nameplate capacity.

We have entered into six 20-year take-or-pay, post-COD SPAs, or the Calcasieu Foundation SPAs, on an FOB basis, which means that the title to the LNG will transfer at the time our customers take delivery at our facilities. Consequently, our customers under our FOB SPAs will bear the risk of loss during transport and the cost of shipping the LNG cargo. The majority of these offtakers have investment grade credit ratings.

The obligation to make LNG available under the Calcasieu Foundation SPAs commences from the occurrence of COD, which is an identical requirement for all six SPAs and a typical construct within the LNG industry. To the extent of any shortfall in supply, we will pay the applicable counterparty to an SPA an amount for shortfall based on a pre-determined formula that takes into account the replacement price or market price for LNG, among other specified factors. This requirement to financially address shortfalls over the 20-year life of the Calcasieu Foundation SPAs underpins the focus on redundancy and reliability to be demonstrated as part of the commissioning phase of construction, prior to achieving COD.

The Calcasieu Foundation SPAs include termination rights in favor of the customer if, among other things, COD did not occur by March 2024, as may be extended in certain circumstances (including, among other things, in connection with aforce majeure event). As a consequence of the occurrence of one such force majeure event, as further described below, the deadline for COD in such SPAs would be extended and we currently anticipate that such customers will not be entitled to terminate as a result of failure to designate COD until June 2025. We have notified all of our customers under the Calcasieu Project post-COD SPAs of the anticipated delay to COD, indicating that such delay resulted from aforce majeure event. All of such customers have questioned whether the delay constitutes aforce majeure event under the contract, in which case they would have a right to terminate their SPAs, generally for a limited duration of time, if COD did not occur by March 2024, and certain of our customers have disputed the validity of our declaration offorce majeure in their respective arbitration proceedings. For more information see Item 1 A.—Risk Factors—Risks Relating to Our Business—Our customers or we may terminate our SPAs if certain conditions are not met or for other reasonsof this Form 10-K. As we continue to commission the facility, we aim to continue to produce commissioning cargos of LNG for export in accordance with all regulatory requirements and subject to the heat recovery steam generator and gas pre-treatment remediation work and other repairs being conducted while the site is made ready for reliability testing. In February 2025, we notified all of our customers that COD for the Calcasieu Project is anticipated to occur on April 15, 2025.

In addition to such 20-year Calcasieu Foundation SPAs, we have entered into a fixed-price three-year take-or-pay SPA for 1 mtpa of the Calcasieu Project’s expected nameplate capacity with Unipec (a subsidiary of Sinopec) and a fixed-price five-year take-or-pay SPA for 0.5 mtpa of the Calcasieu Project’s expected nameplate capacity with CNOOC Gas and Power Singapore Trading & Marketing Pte. Ltd., both on similar terms and conditions as the long-term Calcasieu Foundation SPAs.

We expect that any excess LNG produced by the Calcasieu Project above the nameplate capacity of 10.0 mtpa will be sold to VG Commodities under an Intercompany Excess Capacity SPA for the Calcasieu Project. VG Commodities is party to an LNG sales and purchase agreement, or the VG Commodities BP SPA, with BP Gas Marketing Limited, or BP, pursuant to which, once COD occurs under the Intercompany Excess Capacity SPA for the Calcasieu Project, VG Commodities has contracted to resell at least 50% of the LNG generated by the Calcasieu Project in excess of its nameplate capacity (subject to an annual cap at the option of the buyer). The VG Commodities BP SPA is structured as a 20-year, FOB sales contract, under which BP is required to pay VG Commodities a purchase price for LNG delivered to BP based on a simulated net-back price, which is designed to reflect a profit margin (after deducting related costs) realized from downstream sales of LNG.

(1) Our request to increase the authorized level of exports to Non-FTA Nations from 24.0 mtpa to 27.2 mtpa is still pending. See—Governmental Regulation—DOE Export Authorizations—Plaquemines Projectof this Form 10-K.

(2) Potential bolt-on expansion opportunity based on facility capacity, scale, location and infrastructure. Subject to regulatory approval, among other things. The anticipated timing to implement this expansion opportunity may change based on design considerations, regulatory review process, engagement with contractors and other factors. In addition, implementation of the full amount of potential bolt-on expansion capacity is subject to our ability to secure additional natural gas, pipelines and pipeline transportation capacity. On March 6, 2025, we submitted to FERC a request to initiate the pre-filing process for additional facilities to provide 18.6 mtpa of incremental bolt-on expansion peak production capacity. We aim to file a formal application with FERC in the second half of 2025 and are targeting FID in mid-2027.

(3) Cumulative exports to FTA Nations and Non-FTA Nations cannot exceed the permitted capacity as authorized by the FERC.

Project Construction and Commissioning

The Plaquemines Project is being constructed pursuant to two EPC contracts, one per phase, or the Plaquemines EPC Contracts, that we entered into with KZJV, LLC, or KZJV, a limited liability company that is owned by KBR EPC Member and Zachry Industrial. Under the Plaquemines EPC Contracts, VGPL is responsible for executing or directly managing significant scopes of work. Baker Hughes, UOP and CB&I are each providing and constructing the mid-scale, factory-built liquefaction trains and power island systems, the pre-treatment system, and storage tanks, respectively.

As of December 31, 2024, 28 of the 36 liquefaction trains were delivered to the site. In addition, the Gator Express Pipeline achieved mechanical completion in October 2023 and its laterals were placed in service by FERC in May 2024 and December 2024. While construction remains ongoing, portions of the facility have commenced initial commissioning activities. Our gradual commissioning process starts with addressing identified operational deficiencies, testing individual components and eventually extends to encompass testing and tuning our entire fully-integrated facilities. As an example, one issue that has arisen relates to substantial delays in the operation of our combined cycle power island system. To mitigate such delays, we have permitted and incorporated 400 MW of temporary power at the Plaquemines facility. This allows us to progress commissioning efforts, including the production and sale of commissioning cargos while we complete the construction of our combined cycle power plants.

We currently estimate that the total project costs for the Plaquemines Project will be approximately $23.3 billion to $23.8 billion, including EPC contractor profit and contingency, owners’ costs and financing costs. Of the total project costs for the Plaquemines Project, approximately $19.8 billion had been paid for as of December 31, 2024. Our estimated total project cost remaining is based upon our project cost experiences with the Calcasieu Project and with the Plaquemines Project to date and reflects the current inflationary environment. However, the costs to complete the Plaquemines Project have increased in the past, and may increase further in the future, potentially materially, compared to our current estimates as a result of many factors. Further, these cost estimates do not include the cost of any potential bolt-on capacity at the Plaquemines Project, nor do they reflect the potential impact of any new tariffs that have been announced or implemented since December 31, 2024, or that may be implemented in the future. As a result, the actual project costs for the Plaquemines Project may be materially higher than our current estimates. See Item 1A.—Risk Factors—Risks Relating to Our Projects and Other Assets—Our estimated costs for our projects have been, and continue to be, subject to change due to various factorsof this Form 10-K.

As of December 31, 2024, the Plaquemines Project had executed approximately 68.8 million work hours with a TRIR of 0.21. This safety performance far exceeds the national average for the industry of 1.9 for 2023.

Commissioning LNG Sales

Although designed to be twice as large as the Calcasieu Project on a nameplate basis, the Plaquemines Project utilizes a similar project configuration and development approach to the Calcasieu Project. In contrast to traditional LNG facilities that are constructed by a single EPC contractor and include substantially fewer, larger-size liquefaction trains, our project design and configuration utilizes pioneering, mid-scale, factory-made liquefaction trains and other discrete systems and equipment, which require an extended commissioning period. Given this longer and gradual commissioning period, we expect to produce a substantial number of commissioning cargos. This production occurs during the period in which additional components of the relevant phase are brought into operation, completed and tested (including, if necessary, performing completion and rectification work to address unexpected performance deficiencies), to ensure the project is completed and achieves the performance levels necessary for stable, reliable long-term operations to supply LNG under the project’s post-COD SPAs.

In December 2024, we began to produce LNG at the Plaquemines Project and announced the successful loading and departure of our first commissioning cargo. As of December 31, 2024, the Plaquemines Project had exported one LNG commissioning cargo. This cargo was sold to VG Commodities and ultimately delivered and sold by VG Commodities to an end customer in January 2025.

(1) China Petroleum & Chemical Corp. has signed two separate LNG SPAs for an aggregate supply of 4.0 MTPA.

(2) Approximately 98.5% of the Plaquemines Project's expected 20.0 mtpa nameplate capacity.

(3) Chart does not include the post-COD SPA with Inpex Energy Trading Singapore Pte. Ltd., which is described further below.

As of December 31, 2024, we have entered into thirteen 20-year take-or-pay, post-COD SPAs in connection with the Plaquemines Project, or the Plaquemines Foundation SPAs. The majority of these offtakers have investment grade credit ratings.

The obligation to make LNG available under these SPAs commences from the occurrence of COD, which is bifurcated by Phase 1 or Phase 2, depending on the SPA. All of these SPAs are structured to be delivered on an FOB basis, with the exception of one Phase 1 SPA for 1.2 mtpa, which is structured to be delivered on a DPU basis – requiring us to ship, deliver, and unload LNG to our customer’s designated import facilities. Similar to the Calcasieu Foundation SPAs, the Plaquemines Foundation SPAs include termination rights in favor of the customer if, among other things, COD does not occur by May 2027 or March 2028 for the Phase 1 and Phase 2 SPA, respectively, as may be extended in certain circumstances (including, among other things, in connection with aforce majeure event).

In addition to the Plaquemines Foundation SPAs, we have entered into a short-term, post-COD SPA for 0.3 mtpa of the Plaquemines Project’s expected nameplate capacity with Inpex Energy Trading Singapore Pte. Ltd. on an FOB basis, on similar terms and conditions as the Plaquemines Foundation SPAs.

Any excess LNG produced by the Plaquemines Project above the nameplate capacity of 13.3 mtpa for Phase 1 or above the nameplate capacity of 6.7 mtpa for Phase 2 will be sold to VG Commodities under the applicable Intercompany Excess Capacity SPA.

(1) Anticipated based on capacity, scale, location and infrastructure. Subject to regulatory approval, among other things, and may change based on design considerations, regulatory review process, engagement with contractors, and other factors.

(2) Potential bolt-on expansion opportunity based on facility capacity, scale, location and infrastructure. Subject to regulatory approval, among other things. The anticipated timing to implement this expansion opportunity may change based on design considerations, regulatory review process, engagement with contractors and other factors.

(3) The FERC issued its order authorizing the CP2 Project in June 2024. However, on November 27, 2024, FERC issued an order on rehearing that partially “set aside” its prior analysis of the cumulative air impacts of emissions of nitrogen dioxide (NO2) and particulate matter less than 2.5 micrometers (PM2.5) and to prepare a supplemental Environmental Impact Statement concerning that topic and to address it along with certain other air quality issues in a future order. FERC also announced that, due to its initiation of supplemental environmental review, it will not issue authorizations to proceed with construction until FERC issues a further merits order. On February 7, 2025, FERC issued a draft supplemental Environmental Impact Statement, concluding that the project will have no significant cumulative air quality impacts. Public comments on the draft Environmental Impact Statement are due by March 31, 2025, and FERC’s schedule provides for the final Environmental Impact Statement to be issued by May 9, 2025. Project opponents have also appealed the FERC authorization to the U.S. Court of Appeals for the D.C. Circuit. In response to FERC’s order on rehearing, the D.C. Circuit on December 13, 2024, granted an unopposed motion by FERC to hold the appeal in abeyance, which will delay briefing of the D.C. Circuit appeal. See Item 1A.—Risk Factors—Risks Relating to Regulation and Litigation—We may fail to receive the required approvals and permits from governmental and regulatory agencies for our projects of this Form 10-K.

Project Engineering, Procurement, and Construction

We have completed substantial engineering, procurement, manufacturing, and off-site construction work for the CP2 Project in advance of a final investment decision, which remains subject to certain regulatory approvals, market and other conditions. See—Governmental Regulation and Item 1A.—Risk Factors—Risks Relating to Regulation and Litigation—We may fail to receive the required approvals and permits from governmental and regulatory agencies for our projectsof this Form 10-K.

For the CP2 Project, we anticipate that we will seek to manage additional scopes of work by directly taking on incremental oversight, contract management and coordination responsibilities, based on lessons learned and the relationships we have fostered with construction and fabrication subcontractors while developing the Calcasieu Project and the Plaquemines Project. As of December 31, 2024, we have entered into a number of key contracts to develop and construct the CP2 Project. Such contracts include liquefaction train system and power island system purchase orders with Baker Hughes and an EPC contract for construction of Phase 1 of the CP2 Project, or the CP2 Phase 1 EPC Contract, with Worley Field Services Inc., or Worley. We have also entered into contracts for other discrete portions of the facility, including for LNG storage tanks, gas pre-treatment system licensing, engineering, and procurement agreements and for the construction of the CP2 Project’s perimeter wall.

We currently estimate that the total project costs for the CP2 Project will range between approximately $27.0 billion and $28.0 billion, including EPC contractor profit and contingency, owners’ costs and financing costs, substantially all of which has yet to be funded. Our estimated total project cost is based upon our project cost experiences with the Calcasieu Project and the Plaquemines Project and reflects the current inflationary environment and that the CP2 Project’s pipelines are expected to be longer than the pipelines for the Calcasieu Project and the Plaquemines Project. However, we have not yet entered into an EPC contract for Phase 2 of the CP2 Project or certain other key contracts for the development and construction of the CP2 Project. As a result, there can be no assurance that we will be able to enter into such contracts on similar terms to those for the Calcasieu Project, the Plaquemines Project, and/or Phase 1 of the CP2 Project, as applicable. Further, these cost estimates do not include the cost of any potential bolt-on capacity at the CP2 Project, nor do they reflect the potential impact of any new tariffs that have been announced or implemented since December 31, 2024 or that may be implemented in the future. In addition, certain regulatory approvals and permits must be obtained on a timely basis in order to construct and operate the project, and there can be no assurance that we can obtain and maintain the necessary regulatory approvals and permits to complete the CP2 Project on the anticipated schedule. Accordingly, the actual project costs for the CP2 Project may be materially higher than this estimate. Moreover, the anticipated costs to achieve completion of the CP2 Project have increased in the past, and may increase further in the future, potentially materially, compared to our current estimates as a result of many factors, including delays in construction or commissioning of the project or the execution of any repair or warranty work and change orders under or amendments to certain material construction contracts, including final terms of or amendments to any EPC contract for the CP2 Project, and/or other construction or supply contracts resulting from the occurrence of certain specified events that may give the applicable contractor or supplier the right to cause us to enter into change orders or resulting from changes with which we otherwise agree. See Item 1A.—Risk Factors—Risks Relating to Our Projects and Other Assets—Our estimated costs for our projects have been, and continue to be, subject to change due to various factors of this Form 10-K.

As of December 31, 2024, we have entered into eight 20-year take-or-pay, post-COD SPAs in connection with the CP2 Project, or the CP2 Foundation SPAs, on an FOB basis. These SPAs all relate to Phase 1 of the CP2 Project and equate to 9.25 mtpa of LNG, which is approximately 64% of the expected nameplate capacity for Phase 1 of 14.4 mtpa.

The obligation to make LNG available under these SPAs commences from the occurrence of COD. All of these SPAs are structured for delivery on an FOB basis. Similar to the Calcasieu Foundation SPAs and the Plaquemines Foundation SPAs, the CP2 Foundation SPAs include termination rights in favor of the customer and us if certain conditions precedent are not satisfied by us or waived by the customer by a certain date including that we receive all LNG export authorizations by that date. Such dates certain have passed in two of the CP2 Foundation SPAs and are upcoming in March 2025 in the remaining CP2 Foundation SPAs. As a result, we or some of our customers under the CP2 Foundation SPAs may decide to terminate their SPAs based on such deadlines having passed. See Item 1A.—Risk Factors—Risks Relating to Our Business—Our customers or we may terminate our SPAs if certain conditions are not met or for other reasonsof this Form 10-K. We are negotiating extensions with all of the CP2 Foundation SPA customers related to these date certain deadlines. In addition, our customers also have other limited termination rights if, among other things, COD for Phase 1 does not occur by a date that is approximately 60 months from the satisfaction of such conditions precedent, as may be extended in certain circumstances (including, among other things, in connection with aforce majeure event).

We expect that any excess LNG produced by the CP2 Project above the nameplate capacity of 14.4 mtpa for Phase 1 or above the nameplate capacity of 5.6 mtpa for Phase 2 will be sold to VG Commodities under an Intercompany Excess Capacity SPA (one per phase) to be entered into for the relevant phase.

CP3 Project

(1) Anticipated based on capacity, scale, location and infrastructure, and may change based on design considerations, regulatory review process, engagement with contractors, and other factors. As of the date of this Form 10-K, no FERC and no DOE filings have been made and the necessary approvals for the CP3 Project have not been obtained. Accordingly, this is a target only, based on, among other things, anticipated timeframes for the receipt of the required DOE and FERC approvals. See—Governmental Regulation and Item 1A.—Risk Factors—Risks Relating to Regulation and Litigation—We may fail to receive the required approvals and permits from governmental and regulatory agencies for our projects.

Project Development

As of December 31, 2024, we have completed significant engineering studies and simulations, including certain marine berth simulations, in support of the project.

Although we have completed our initial consultation with FERC in December 2024, as of December 31, 2024, we had not initiated the pre-filing process for the CP3 Project with FERC or entered into definitive agreements with an EPC contractor or other key advisors and contractors necessary for the project’s development and construction. However, we have ample capacity under the Baker Hughes Master Agreement to contract for the potential supply of liquefaction trains and power island systems, which we expect to utilize for the CP3 Project. We expect that the construction, commissioning and operational start-up of the liquefaction plant will be substantially similar to our other projects.

Delta Project

(1) Location and acreage for project site may change based on project execution priorities, design considerations, regulatory review process, engagement with contractors, and other factors..

(2) Anticipated based on capacity, scale, location and infrastructure, and may change based on design considerations, regulatory review process, engagement with contractors, and other factors. As of the date of this Form 10-K, definitive FERC and DOE filings have not been made and the necessary approvals for the Delta Project have not been obtained. Accordingly, this is a target only, based on, among other things, anticipated timeframes for the receipt of the required DOE and FERC approvals. See—Governmental Regulation and Item 1A.—Risk Factors—Risks Relating to Regulation and Litigation—We may fail to receive the required approvals and permits from governmental and regulatory agencies for our projects.

(3) Potential bolt-on expansion opportunity based on facility capacity, scale, location and infrastructure. Subject to regulatory approval, among other things, and may change based on design considerations, regulatory review process, engagement with contractors and other factors.

Project Development

We initiated the pre-filing process for the Delta Project with FERC in April 2019; however, we have informed FERC that, if FERC confirms the acceptance of the potential bolt-on expansion at the Plaquemines Project into the NEPA pre-filing review process, we will withdraw the Delta Project from the pre-filing process. In addition, we have not yet entered into definitive agreements with an EPC contractor or other key advisors and contractors necessary for the project’s development and construction. However, we have ample capacity under the Baker Hughes Master Agreement to contract for the potential supply of liquefaction trains and power island systems, which we expect to utilize for the Delta Project. We expect that the construction, commissioning and operational start-up of the liquefaction plant will be substantially similar to our other projects.

Natural Gas Supply and Transportation

Natural Gas Supply Portfolio Approach

To the extent we produce LNG for export pursuant to our existing SPAs, we are responsible for procuring natural gas and transporting it to the relevant facility for liquefaction. We have entered into a portfolio of natural gas supply agreements with domestic natural gas suppliers to supply feed gas to the Calcasieu Project and the Plaquemines Project, which we continue to expand to suit the needs of our projects. We also anticipate entering into long-term natural gas supply arrangements with large upstream gas producers that will integrate their gathering and processing facilities into our planned pipeline network and deliver natural gas to our project facilities for liquefaction. Assuming we are able to operate our projects at their expected peak production capacity, we anticipate that we will require approximately 1.9 Bcf/d of natural gas for the Calcasieu Project, 4.2 Bcf/d of natural gas for the Plaquemines Project, 4.3 Bcf/d of natural gas for the CP2 Project, 6.5 Bcf/d of natural gas for the CP3 Project, and 5.3 Bcf/d of natural gas for the Delta Project. These estimates do not account for any bolt-on expansions. We have constructed lateral pipelines to connect the Calcasieu Project and the Plaquemines Project to the ANR Pipeline Company, Texas Eastern Transmission LP, and Sabine Pipe Line systems, and the Columbia Gulf, Texas Eastern Transmission LP, and Tennessee Gas Pipeline systems, respectively. Similarly, we intend to construct pipelines to connect our other current projects and any other future projects we may seek to develop to major interstate and intrastate pipelines. In addition, as described below, we aim to own other natural gas pipelines that support or, when constructed, will support our production facilities. Such connections allow us to access highly liquid upstream supplies.

Natural Gas Transportation: Contracted Pipeline Capacity and Pipeline Development

We are developing, permitting, constructing and securing transport capacity agreements for midstream natural gas pipeline infrastructure that is intended to support our liquefaction growth strategy and help ensure stable and cost-effective access to the natural gas that fuels our LNG exports.

We have entered into a number of transport capacity agreements and related service agreements with interstate pipeline companies to provide the natural gas transportation to the Calcasieu Project and the Plaquemines Project. The Calcasieu Project and the Plaquemines Project were each sited and sized to facilitate ready connectivity to existing natural gas pipeline network infrastructure with the construction of short-run lateral pipelines. These lateral pipelines (the TransCameron Pipeline and the Gator Express Pipeline), and the major, third-party interstate pipelines to which they are connected, provide natural gas supply primarily from two major shale formations – the Haynesville and the Marcellus/Utica plays – though there is access to other U.S. shale basins though interconnects into the third-party interstate pipelines.

Our existing gas transportation agreements for the Calcasieu Project and the Plaquemines Project are long-term commitments of approximately 20 years from the commencement of service, with extension rights following the initial term.

We have acquired all of the land rights required to construct and operate the TransCameron Pipeline and the Gator Express Pipeline for the Calcasieu Project and the Plaquemines Project, respectively. We are also currently in the process of securing servitudes, rights of way, crossing agreements, and any permits necessary for us to construct the interstate and intrastate pipelines discussed below, lateral pipelines and related infrastructure required to interconnect the CP2 Project, the CP3 Project and the Delta Project with existing interstate and intrastate natural gas pipeline systems.

The TransCameron Pipeline is the lateral pipeline that delivers natural gas to the Calcasieu Project. The Calcasieu Project holds firm transport capacity of 2.35 TBtu/day on several pipeline systems delivering into its TransCameron supply header system including ANR Pipeline Company, Texas Eastern Transmission LP, and Sabine Pipe Line systems. Additionally, the Calcasieu Project holds firm transport capacity of 700,000 Dth/d, reducing to 625,000 Dth/d in April 2025, on the TC Louisiana Intrastate Pipeline, providing the ability to transport Haynesville production into ANR Pipeline for both supply security and beneficial pricing. The TransCameron Pipeline achieved substantial completion in April 2021 and final completion in July 2021 and has been commissioned and placed in service by FERC.

The Gator Express Pipeline is the lateral pipeline that delivers natural gas to the Plaquemines Project. The Plaquemines Project holds firm transport capacity of 4.225 TBtu/day on several pipeline systems delivering into its Gator Express supply header system including Columbia Gulf, Texas Eastern Transmission LP, and Tennessee Gas Pipeline systems. Additionally, the Plaquemines Project holds firm transport capacity of 575,000 Dth/d on the TC Louisiana Intrastate Pipeline, providing the ability to transport Haynesville production into Columbia Gulf for both supply security and beneficial pricing. The Gator Express Pipeline achieved mechanical completion in October 2023 and its laterals were placed in service by FERC in May 2024 and in December 2024.

The proposed CP Express Pipeline will deliver natural gas to the CP2 Project and will consist of 85.4 miles of 48-inch-diameter natural gas pipeline in Jasper and Newton Counties, Texas and Calcasieu and Cameron Parishes, Louisiana, and a 6.0-mile-long, 24-inch-diameter lateral off that mainline in northwest Calcasieu Parish. For the CP Express Pipeline we have secured an agreement, subject to FID of the CP2 Project, for firm transport capacity on the TC Louisiana Intrastate Pipeline LLC (1.4 TBtu/day expanding to 1.9 TBtu/day) to transport Haynesville production into the CP Express Pipeline in Louisiana. In addition, subject to CP2 Project requirements, we expect the CP

Express Pipeline will interconnect with additional upstream pipeline infrastructure that secures delivery of gas from additional production basins.

We are in the development and siting process to optimize the plans for the pipelines to support the potential bolt-on expansion for the Plaquemines Project, the CP3 Project and the Delta Project.

As we are expanding our development footprint with the CP2 Project, the CP3 Project and the Delta Project, these projects’ production capacities are anticipated to require natural gas volumes that will support the construction of longer interstate and intrastate pipelines that provide incremental access and delivery capability from the Permian, Haynesville, Western Haynesville, Eagle Ford and mid-continent shale formations.

We plan to construct significant pipeline infrastructure, both independently and in partnership with certain qualified third parties, sufficient to source the required natural gas for these projects from primarily the Permian, Haynesville and Western Haynesville shale plays.

For example, we have partnered with WhiteWater Midstream, LLC, a Texas-based pipeline developer and operator, and through our wholly-owned subsidiary Venture Global Midstream Holdings, LLC, have entered into an agreement with WhiteWater Blackfin Holdings, LLC pursuant to which we have committed to jointly develop, permit, and site the 190 mile Blackfin pipeline project, which upon construction is expected to include a long-haul 48-inch intrastate pipeline designed to facilitate the transportation of Permian sourced gas from the Matterhorn Express pipeline to certain interconnecting pipelines, including the CP Express Pipeline. Under the agreement, we have agreed to fund certain construction and development costs and seek to arrange a financing to support the Blackfin pipeline project. We have secured firm transport capacity on Matterhorn Express Pipeline, LLC (2.0 TBtu/day, expanding to 3.3 TBtu/day) that will feed into the Blackfin pipeline.

We have also commenced early development activities for two additional long-haul pipeline projects to support our planned development projects. The first pipeline project is anticipated to be an approximately 291 mile, 48-inch intrastate pipeline in Louisiana that is designed to transport up to approximately 4.5 TBtu/day of natural gas from northeast Louisiana close to our projects located in Plaquemines Parish, including our contemplated expansion project at our Plaquemines Project. The second pipeline project is anticipated to be an approximately 644 mile, dual, 48-inch intrastate pipeline in Texas that is designed to transport up to approximately 6.5 TBtu/day of natural gas from the Permian Basin to Eastern Texas, which is proximate to our CP3 Project located in Cameron Parish, Louisiana.

Major Consultants and Contractors

In conjunction with our owner-led procurement and management approach, we are working with a team of consultants and contractors that assist us with the development, engineering, financing, construction, permitting, marketing and operation of our projects. The conventional approach utilized by developers for large-scale projects typically relies on a single, comprehensive EPC contract, delegating all or substantially all responsibility to construct a project to a single EPC contractor. In contrast, we decentralize the contracting approach for our projects and seek to manage key scopes of work directly with a collection of key contractors, each of which are experts in particular systems and equipment.

To implement our “design one, build many” approach, we have entered into the Baker Hughes Master Agreement that grants us the option to order significant quantities of liquefaction trains and power island systems for the projects that we develop. For each of our projects, we also enter into certain design, procurement, and construction contracts for other key equipment and facilities such as the pre-treatment system, LNG storage tanks, perimeter wall, and marine facilities. As of December 31, 2024, we have entered into the Calcasieu EPC Contract, the Plaquemines EPC Contracts, the CP2 Phase 1 EPC Contract, the Baker Hughes Master Agreement, purchase orders with Baker Hughes, and several construction or procurement contracts for other key equipment and components of the Calcasieu Project, the Plaquemines Project and the CP2 Project. To the extent not yet in place, we aim to negotiate and to enter into agreements on similar terms to those for the Calcasieu Project and the Plaquemines Project for the construction of our development projects.

Baker Hughes

The Baker Hughes Master Agreement provides for the supply of substantial incremental nameplate liquefaction and power equipment well in excess of the expected 104.4 mtpa nameplate capacity of our current project portfolio. Subject to our compliance with the Baker Hughes Master Agreement, such incremental equipment can be utilized for our development projects and any bolt-on expansions or additional projects that we may seek to develop in the future. Under the Baker Hughes Master Agreement, Baker Hughes is required to supply such equipment at an agreed upon price and schedule with reserved manufacturing capacity.

Purchase orders under the Baker Hughes Master Agreement contain terms and conditions, scope of supply, delivery schedule and performance tests and performance guarantees. We are limited under this agreement from contracting with an alternate equipment supplier to Baker Hughes, even in the event our preference is to do so. All of the liquefaction purchase orders and power island system purchase orders for the Calcasieu Project, the Plaquemines Project, and the CP2 Project follow the terms and conditions specified in the applicable form purchase order included in the Baker Hughes Master Agreement.

Under the Baker Hughes Master Agreement and related purchase orders, Baker Hughes has committed to satisfy key performance, reliability and LNG quality guarantees for the liquefaction and, as applicable, power equipment it supplies. In particular, if the relevant equipment fails to pass specified performance tests, then Baker Hughes is required to perform all work necessary to cause those systems to successfully pass the performance tests at its own expense or pay liquidated damages under certain performance guarantees.

Baker Hughes has agreed to reserve dedicated manufacturing capacity for the required components for our projects, which is sufficient to cover our five existing and contemplated projects, as well as incremental capacity that can be utilized for bolt-on expansions or future projects. The obligation to reserve manufacturing capacity expires in a staggered manner if we do not execute definitive purchase orders for the applicable portions of these components by certain mutually agreed dates. We have already executed the necessary purchase orders for the Calcasieu Project, the Plaquemines Project, and the CP2 Project and, based on our anticipated project schedule and barring unforeseen delays, we currently expect that we will be in a position to deliver the purchase orders for the CP3 Project, the Delta Project, or for any potential bolt-on expansions to Baker Hughes by the applicable deadlines in the Baker Hughes Master Agreement, as those deadlines may be amended from time to time.

In addition to the reservation of manufacturing capacity, the Baker Hughes Master Agreement contains an agreed upon price structure and schedule for the equipment that Baker Hughes is obligated to supply, except for certain alternative configurations of power island systems, in which case the agreed upon price structure and schedule is adjusted. The Baker Hughes Master Agreement generally provides for various staggered delivery dates for the first delivery of components, subject to the determination of final technical details of the equipment supplied as well as the terms of their respective purchase orders. Furthermore, we and Baker Hughes have agreed upon the pricing framework for the various components required for our liquefaction systems, which remain subject to adjustments based on changes to the scope of equipment and/or operations, negotiations in good faith and/or other modifications pursuant to the terms and conditions of the purchase orders when delivered.

The Baker Hughes Master Agreement includes pre-negotiated forms of purchase orders for the supply of liquefaction systems and power plants. Each purchase order is required to contain terms and conditions, scope of supply, delivery schedule and performance tests and performance guarantees. Unless and until we execute purchase orders for the equipment and issue notices to proceed under those orders, neither we nor Baker Hughes has any binding obligations with respect to the supply of any equipment under the Baker Hughes Master Agreement. Once we execute any purchase order with Baker Hughes for the supply of equipment, we may terminate that purchase order at our discretion. However, if we do terminate any purchase order, we are required to pay a termination fee to Baker Hughes, which is intended to reflect the out-of-pocket costs that Baker Hughes expects to incur in connection with such termination that it is not able to mitigate. As a result, if termination occurs in the mid-to-late stage of Baker Hughes’ performance of a purchase order, the termination fee payable in respect of that purchase order would approach, but would not exceed, the contract price for that purchase order.

In addition, we have the right under the Baker Hughes Master Agreement to require Baker Hughes to enter into long-term service agreements on specified terms with respect to long-term maintenance, repair, and servicing of the liquefaction, power, and booster compressor equipment it supplies. We exercised such right for the Calcasieu Project and the Plaquemines Project and signed such long-term service agreements with Baker Hughes in December 2022 and December 2024, respectively. Moreover, pursuant to the form long-term service agreement and the Calcasieu Project’s long-term service agreement, Baker Hughes is required to provide a long-term availability guarantee whereby Baker Hughes guarantees that the equipment it supplies will reach a minimum annual operating availability. If the equipment Baker Hughes supplies is unable to reach the specified operating availability, liquidated damages will be payable by Baker Hughes. To the extent the liquefaction system reaches an operating availability in excess of a certain level, we would be obligated under any such long-term service agreement to pay Baker Hughes a bonus based upon the amount of such excess. Both Baker Hughes’ and our respective obligations under this long-term service agreement would be subject to certain agreed limitations on liability.

EPC Contracts

Our project companies directly negotiate and contract with, as well as oversee and manage, our equipment vendors for the delivery of the majority of the critical facilities and modules related to LNG production. While we also typically engage an EPC contractor, such EPC contractors increasingly have a limited work scope, far less than for traditional facilities.

We constructed the Calcasieu Project pursuant to an EPC contract and have certified that it was performed in February 2023, subject to customary warranty obligations. In addition, we have entered into EPC contracts for both phases of the Plaquemines Project and for Phase 1 of the CP2 Project that require that the applicable contractor integrate such equipment and facilities and guarantee the full operation of the LNG export facilities. The services under the EPC contracts include contributing to the (i) design of balance of the plant and all interconnections including piping, utilities and associated infrastructure, (ii) procurement of all items not covered by our other construction and supply agreements, (iii) scheduling and coordination of the work and services performed by certain subcontractors and other contractors, (iv) site preparation, (v) installation and connection of all equipment supplied by our equipment suppliers, (vi) construction of the power plant forming part of the project, (vii) compliance with the contractor’s warranty obligations and all applicable laws, codes and standards, and (viii) provision of project controls and construction performance indicators and invoice reconciliation.

Under each such contract that we have entered into for our projects, the EPC contractor has an uncapped make-good obligation to deliver a facility capable of passing certain performance tests. Each contractor is also required to pay us liquidated damages, subject to a specified cap and sub-limits for certain milestones, for any construction and/or performance testing delay. The aggregate amount of liquidated damages that would be payable under this arrangement with respect to each of these projects, in addition to the liquidated damages that would be payable under certain performance guarantees under the applicable liquefaction and power equipment purchase orders entered into pursuant to the Baker Hughes Master Agreement, are expected to be up to 10% of the aggregate construction cost for each project.

Further, under each such contract, the EPC contractor warrants that (i) it will perform the work under the EPC contract in full compliance with such contract, (ii) the materials and the work will be designed, manufactured, engineered, constructed, completed, pre-commissioned, commissioned, tested and delivered in a workmanlike manner and in accordance with each respective EPC contract, our standards, all permits and approvals of government authorities, applicable codes and standards and all applicable laws, (iii) the work will conform to the specifications and descriptions in its EPC contract, will be new, complete, and of suitable grade for the intended function and use, will be free from defects in design, material and workmanship, and will meet the requirements set forth in its EPC contract, (iv) the materials will be composed and made of only proven technology, of a type in commercial operation at the effective date of its EPC contract, (v) if a serial defect (two or more of the same components experience a defect of an identical or nearly identical nature) occurs as to its work done under the EPC contract prior to the expiration of each respective warranty period, it will redesign, repair or replace any materials as necessary and extend each respective warranty period for that portion of the work that is redesigned, repaired or replaced for an additional 12 months, and (vi) during the warranty period, it will perform tests, inspections or other diagnostic services requested by us and correct any non-conforming work discovered.

For Phase 2 of the CP2 Project and our other development projects, we aim to negotiate and enter into EPC contracts on similar terms as described above. However, as compared to the Calcasieu Project, the Plaquemines Project and Phase 1 of the CP2 Project, we aim to manage additional scopes of work directly. Specifically, we anticipate that we will perform additional construction oversight activities and deploy labor that we recruit to leverage lessons learned and the relationships fostered with construction and fabrication subcontractors while developing the Calcasieu Project and the Plaquemines Project, which we believe will help improve construction efficiency and reduce total costs for such projects.

Below is a summary of the Plaquemines EPC Contracts and the CP2 Phase 1 EPC Contract.

Plaquemines EPC Contracts

The Plaquemines EPC Contracts are separate contracts for Phase 1 and Phase 2 of the Plaquemines Project under which KZJV is the EPC contractor and which reflects the terms described above.

Under the Plaquemines EPC Contracts, KZJV will be paid a reimbursable sum for its scope of work, where we will reimburse KZJV for all reimbursable costs incurred in connection with the relevant work (such as costs for materials, transportation and equipment), plus a margin to cover overhead costs and expenses as well as an agreed profit margin. However, all other costs will not be reimbursed and will be borne by KZJV. The estimated reimbursable sum represents the “target price” for each phase of the Plaquemines Project, which is reflected in our estimated total cost for the Plaquemines Project. The target price is subject to adjustment under certain limited conditions, including pursuant to change orders we could submit with respect to the scope of work to be performed by KZJV or the project schedule.

The Plaquemines EPC Contracts establish an agreed project schedule for the applicable phase, including substantial completion deadlines and final completion deadlines, based on the achievement of the contractual conditions regarding the commissioning and completion of the LNG production systems that comprise Phases 1 and 2 of the Plaquemines Project, which may only be adjusted by change orders as provided in the Plaquemines EPC Contracts. Each of the project schedule milestones requires that the work performed meets or exceeds requirements under the Plaquemines EPC Contracts and certain material project schedule milestones additionally require that the work performed passes performance tests. KZJV has significant milestone and schedule-driven bonus incentives under the Plaquemines EPC Contracts that are intended to promote schedule adherence and a completion mindset. If KZJV fails to successfully pass the performance tests by the applicable deadlines for these milestones for reasons not caused by us or our other contractors, KZJV is obligated to perform all work necessary to successfully pass such tests at its own expense. Additionally, if KZJV exceeds the target price by certain agreed amounts, we could reduce KZJV’s profit margin according to certain predetermined thresholds and if KZJV incurs delays in the project schedule beyond certain deadlines, KZJV could potentially owe us liquidated damages (subject to specified caps). Conversely, if KZJV’s reimbursable costs are below the applicable target price or if KZJV completes certain work ahead of the applicable target schedule, (i) KZJV will be entitled to a share in certain benefits of cost savings and (ii) KZJV will receive incentive payments for early completion of certain milestones.

CP2 Phase 1 EPC Contract

Worley is the contractor under the CP2 Phase 1 EPC Contract. The CP2 Phase 1 EPC Contract is comparable in scope and terms to the Plaquemines EPC Contracts, with certain adjustments to account for the CP2 Project’s schedule and minor configuration differences. The CP2 Phase 1 EPC Contract also includes substantial completion deadlines and final completion deadlines, with associated bonus incentives and exposure to liquidated damages depending on adherence to the project’s schedule.

Like the Plaquemines EPC Contracts, under the CP2 Phase 1 EPC Contract, Worley will be paid a reimbursable sum for its scope of work under similar terms to those included in the Plaquemines EPC Contracts.

However, we anticipate that we will seek to manage additional scopes of work directly acting as EPCM, based on lessons learned and the relationships we have fostered with construction and fabrication subcontractors while developing the Calcasieu Project and the Plaquemines Project. The target price under the CP2 Phase 1 EPC Contract is subject to adjustment under certain limited conditions, including pursuant to change orders we could submit with respect to the scope of work to be performed by Worley or the project schedule.

Human Capital Resources

Our human capital is our most valuable asset, and we place a high premium on attracting, developing and retaining talented and high performing employees. As of December 31, 2024, we had over 1,500 full-time employees working on our engineering, project development, project financing, corporate finance, legal, and LNG marketing teams. As we develop and construct our projects, we expect to create additional highly skilled engineering, construction, manufacturing, and operating full-time and contractor jobs in Louisiana, Texas, and Virginia. We offer our employees a wide array of company-paid benefits and performance incentives, which we believe are competitive relative to others in our industry. Our employees are not represented by a labor union or covered by a collective bargaining agreement. We believe our relationship with our employees to be good.

Community Outreach

We aspire to set the standard for our industry in achieving positive impacts for our local communities and on a national level. In connection with the development of our projects, we provide substantial direct and indirect employment opportunities and have been a significant contributor to the domestic labor market with the jobs that we have created and supported. Taken together, we estimate that the Calcasieu Project and the Plaquemines Project have been supported by over 300 subcontractors across the country. At peak, we estimate that we have supported the employment of up to 9,000 construction jobs to construct the Calcasieu Project and the Plaquemines Project. We expect to directly hire approximately 800 permanent employees to operate and manage such projects and have already filled substantially all of these positions.

We strive to hire in-state and local workers where possible and, as of December 31, 2024, over 90% of the direct employees at the Calcasieu Project and the Plaquemines Project are from Louisiana. We anticipate that the CP2 Project will support the employment of over 7,500 on-site construction jobs at its peak and we expect to hire over 400 workers in permanent operational positions.

Further, we engage with the communities near our project sites by providing full-time employment and educational opportunities that allow local residents to develop new technical skills and succeed in related careers. We primarily pursue this through our “Will to Skill” program and our apprenticeship program. In 2020, we established our educational “Will to Skill” program in partnership with local colleges to provide technical training certifications to residents of the communities near our projects. As of December 31, 2024, over 350 individuals have graduated in the aggregate from the 30 cohorts of the Will to Skill program that we have offered in the various communities located near our project sites. Will to Skill participants graduate with occupational and industrial certifications that include construction, electrical, welding, maritime, and trucking skills. Additionally, in October 2023, we established a new apprenticeship program to provide a 12-month training program to local residents near Lake Charles, Louisiana. Upon the successful completion of the program, individuals are eligible to transition to full-time Venture Global employees as field operators and maintenance technicians.

Finally, we are a major financial supporter of the local communities in which we operate and have undertaken a multitude of community development and engagement activities. In particular, over the lifecycle of the Calcasieu Project, Plaquemines Project, and CP2 Project, we expect Venture Global will pay in excess of $7.0 billion in total parish property taxes.

Health and Safety

We are committed to providing a safe work environment across our businesses and strive towards best in class practices. We have built a dedicated Health, Safety, Security, and Environment, or HSSE, team that is accountable for the safe and responsible execution of our projects and reports to our Chief Operating Officer. At our project sites, our goal is to implement comprehensive safety programs that are appropriate for the hazards present at the various stages of construction and commissioning. This includes daily safety inspections, recurring safety trainings, and regular safety meetings. Our rigorous safety standards are continuously reviewed and updated to ensure they are fit for purpose within our workforce and we aim to meet the highest possible benchmarks. We believe that a strong safety culture leads to better safety performance, better operational performance, and higher staff morale. Our aggregate 0.18 TRIR which, when compared to the industry average for 2023 of 1.9 according to the Bureau of Labor safety statistics, is among the best in our industry and stands as testament to our commitments.

Governmental Regulation

Our operations are subject to extensive federal, state, and local regulation. Applicable laws require us to consult with applicable federal and state agencies, obtain and maintain applicable permits and authorizations, and comply with various ongoing regulatory requirements. This regulatory burden increases the cost of constructing and operating our projects, and failure to comply with such laws could result in substantial penalties and/or loss of necessary authorizations. See Item 1A.—Risk Factors—Risk Relating to Regulation and Litigation—We may fail to receive the required approvals and permits from governmental and regulatory agencies for our projects of this Form 10-K for more information.

Federal Energy Regulatory Commission (FERC)

The siting, construction, and operation of our natural gas liquefaction and export facilities are subject to FERC’s approval and ongoing regulation, as is the construction and operation of our natural gas pipelines.

Pursuant to the Natural Gas Act, or the NGA, any person proposing to site, construct, or operate facilities (including LNG terminals) to be used for the export of natural gas from the United States to a foreign country must obtain authorization from FERC. FERC exercises comprehensive regulation of interstate natural gas pipelines, including requiring a certificate of public convenience and necessity to construct and operate such a pipeline, and requiring that the rates and terms of service for pipeline transportation service be just and reasonable under the NGA.

In addition to the initial FERC process for each of our projects summarized below, we note that throughout the life of each project, our LNG and pipeline facilities will be subject to ongoing FERC regulation and reporting requirements (as well as those of various other federal, state and local regulatory agencies). FERC’s jurisdiction under the NGA and NGPA allows it to impose civil and criminal penalties for any violations of the NGA or NGPA, and any rules, regulations or orders of FERC up to approximately $1.58 million per day per violation, including any conduct that violates the NGA’s prohibition against market manipulation.

On February 21, 2019, FERC authorized the Calcasieu Project, as well as the construction and operation of the TransCameron Pipeline, subject to numerous conditions, or the Calcasieu FERC Order.

Construction and commissioning of the Calcasieu Project is subject to ongoing oversight by FERC and the Calcasieu FERC Order imposes ongoing conditions with which we must comply. On February 11, 2022, FERC authorized the export of our first LNG cargo, and we loaded our first commissioning cargo on March 1, 2022. Although we have completed most of the construction of the Calcasieu Project, the commissioning phase remains ongoing. On March 28, 2023, we submitted to FERC an update regarding commissioning and certain reliability challenges and needed repairs and replacements, and FERC authorized our remediation plans on October 12, 2023.

With the requisite authorization, the TransCameron Pipeline was placed in service by FERC in April 2021.

On September 22, 2023, FERC approved an amendment to our FERC authorizations for the Calcasieu Project to increase the permitted capacity under optimal conditions from 12.0 to 12.4 mtpa, subject to certain conditions.

On February 15, 2024, we submitted to FERC a request for a one-year extension of time, if deemed necessary, to the in-service condition in the Calcasieu FERC Order. The extension request remains pending at FERC.

On September 30, 2019, FERC authorized the Plaquemines Project, as well as the construction and operation of the Gator Express Pipeline, subject to numerous conditions, or the Plaquemines FERC Order. Construction of the Plaquemines Project is subject to ongoing oversight by FERC and the Plaquemines FERC Order imposes ongoing conditions with which we must comply.

With the requisite authorization, the two Gator Express lateral pipelines were placed in service by FERC in May 2024 and December 2024.

On March 11, 2022, we submitted an application with FERC to amend the terms of our FERC authorization to increase the authorized permitted production capacity under optimal conditions from 24.0 to 27.2 mtpa. This “uprate” in the regulatorily authorized production capacity is based on updated engineering and vendor data, and does not involve the construction of any new facilities nor any modification of the previously authorized facilities. FERC issued an order approving this uprate amendment application on February 19, 2025.

On March 6, 2025, we made a formal request to FERC to initiate the Commission’s National Environmental Policy Act, or NEPA, pre-filing review process for bolt-on expansion capacity at our current Plaquemines Project, or the Plaquemines Expansion Project. Subject to regulatory approval, among other things, and our ability to secure additional natural gas, pipelines and pipeline transportation capacity, we anticipate that the Plaquemines Expansion Project will involve the construction and operation of new liquefaction facilities capable of producing incremental peak capacity of 18.6 mtpa on a 600-acre site controlled by one of our subsidiaries and located immediately adjacent to the current Plaquemines Project. We aim to file a formal application for the Plaquemines Expansion Project with FERC in the second half of 2025.

On June 27, 2024, FERC authorized the CP2 Project, as well as the construction and operation of the CP Express Pipeline, subject to numerous conditions, or the CP2 Project FERC Order. In July 2024, a group of opponents composed mostly of environmental groups filed a request for rehearing of the FERC authorization, raising a number of challenges to the FERC authorization. In a notice issued in August 2024, FERC denied rehearing by operation of law while providing for further consideration. Project opponents consisting of numerous environmentalist organizations and certain individuals filed petitions for review of FERC’s authorization order with the US Court of Appeals for the D.C. Circuit on September 4, 2024. FERC denied a motion for stay of its authorization order on October 1, 2024. The D.C. Circuit denied a similar request for stay filed by project opponents on November 8, 2024, and established a briefing schedule through April 2025.

On November 27, 2024, FERC issued an order on rehearing that generally rejected the arguments opposing the CP2 Project and noted that it remains confident in the authorization order, but decided to partially “set aside” its prior analysis of the cumulative air impacts of emissions of nitrogen dioxide (NO 2) and particulate matter less than 2.5 micrometers (PM 2.5) and to prepare a supplemental Environmental Impact Statement concerning that topic and to address it along with certain other air quality issues in a future order. FERC also announced that, due to its initiation of supplemental environmental review, it will not issue authorizations to proceed with construction until the Commission issues a further merits order. In response to FERC’s order on rehearing, the D.C. Circuit on December 13, 2024, granted an unopposed motion by FERC to hold the appeal in abeyance. On February 7, 2025, FERC issued a draft supplemental Environmental Impact Statement, concluding that the project will have no significant cumulative air quality impacts and that all its previous environmental conclusions remain unchanged. Public comments on the draft Environmental Impact Statement are due by March 31, 2025, and FERC’s schedule provides for the final Environmental Impact Statement to be issued by May 9, 2025.

In addition to the supplemental environmental review and the appeal, construction of the CP2 Project will be subject to ongoing oversight by FERC in accordance with the terms and conditions of the CP2 Project FERC Order. While we have already begun to submit implementation plans for this purpose, FERC has not yet authorized any on-site construction as of the date of this Form 10-K.

CP3 Project and Delta Project

We have not yet submitted a formal FERC application for the CP3 Project or the Delta Project. Such approvals are subject to a number of risks, and there can be no assurances as to when we will file the formal applications or when we will receive the approvals, if at all.

DOE Export Authorizations

Section 3 of the NGA requires any person seeking to import natural gas from, or export natural gas to, a foreign country to obtain authorization from the DOE. The DOE’s Office of Fossil Energy and Carbon Management, or DOE/FECM, reviews applications to import or export natural gas.

The NGA sets forth separate standards of review for exports to (1) countries with which the United States has a free trade agreement requiring national treatment for trade in natural gas, or FTA Nations, and (2) countries with which there is no such free trade agreement in effect, or Non-FTA Nations. Applications seeking authorization to export LNG to FTA Nations are deemed consistent with the public interest and must be granted without modification or delay. FTA Nations currently include Australia, Bahrain, Canada, Chile, Colombia, Dominican Republic, El Salvador, Guatemala, Honduras, Jordan, Mexico, Morocco, Nicaragua, Oman, Panama, Peru, Republic of Korea, and Singapore. In contrast, Non-FTA Nations export applications are subject to a public interest review. DOE/FECM will grant the requested authorization unless it finds, after providing for a public comment period, that the proposed exports will be inconsistent with the public interest, and may approve an application in whole or in part, and with such modifications and upon such terms and conditions as it deems necessary or appropriate. DOE/FECM’s established practice is to act on long-term authorizations to export to Non-FTA Nations only after the FERC has authorized the siting, construction and operation of the associated LNG facilities.

In January 2024, the Biden administration announced a temporary pause on new authorizations of natural gas exports to Non-FTA Nations while the DOE conducts studies to update its analyses regarding whether the exports are “not inconsistent with the public interest” to consider the latest available information regarding macro-economic impacts, domestic energy prices, potential greenhouse gas, or GHG, or climate or other environmental effects, and national security implications. On July 1, 2024, a federal court in Louisiana granted a motion for preliminary injunction filed by numerous states, holding the DOE pause appears to be unlawful and staying the pause in its entirety.

On December 17, 2024, DOE publicly released a multi-volume study of its views of the potential effects of U.S. LNG exports on the domestic economy; U.S. households and consumers; communities that live near locations where natural gas is produced or exported; domestic and international energy security, including effects of U.S. trading partners; and the environment and climate. DOE stated that it intends to use this study to inform its public interest review of and future decisions regarding exports to Non-FTA Nations. The study was initially subject to a public comment period scheduled to expire on February 18, 2025.

On January 20, 2025, the Trump administration issued an Executive Order entitled “Unleashing American Energy,” that, among other provisions, directed DOE to restart reviews of applications for approvals of LNG exports and directed the consideration of the economic and employment impacts to the U.S. and the impact to the security of allies and partners that would result from granting the application. Other parts of the wide-ranging Executive Order require expedited permitting and elimination of delays and revoke prior executive orders related to the CEQ and GHG emissions. A second Executive Order issued that same day declared a “National Energy Emergency” and, among other things, recognized the benefits of selling LNG to international allies and partners. On January 21, 2025, DOE directed the Office of Fossil Energy and Carbon Management to resume consideration of pending applications for LNG exports in accordance with the NGA and extended the comment period on the DOE study to March 20, 2025 “to ensure such public interest determinations receive appropriate stakeholder input.” The first Secretarial Order issued by new DOE Secretary Wright on February 5, 2025, stated that DOE has resumed consideration of pending export authorizations and will identify and exercise its legal authorities to expedite the approval and construction of reliable energy infrastructure. On February 14, 2025, DOE Secretary Wright announced the issuance of a conditional authorization to export LNG to Non-FTA Nations to Commonwealth LNG. Nevertheless, there can be no assurance as to DOE’s further implementation of the Executive Orders, the Trump administration’s views of the recently released DOE study or its future policies, or the impact of those policies on our existing and future projects, including the applications described below, or on any contracts related to our existing and future projects. For more information on these risks, see Item 1A.—Risk Factors—Risks Relating to Regulation and Litigation—We may fail to receive the required approvals and permits from governmental and regulatory agencies for our projects of this Form 10-K.

DOE/FECM approved our applications for exports from the Calcasieu Project to FTA Nations in May 2013 for 5 mtpa, in May 2014 for an additional 5 mtpa, and in February 2015 for an additional 2 mtpa, for a total volume of 620 Bcf/yr of natural gas (equivalent to 12 mtpa), and originally for a term of 25 years beginning the earlier of (i) the date of first export or (ii) seven or eight years (depending on the specific terms of each authorization) from the date of the authorization. DOE/FECM granted us long-term authorization for export to Non-FTA Nations on March 5, 2019. The non-FTA export authorization also is for up to 620 Bcf/yr of natural gas (equivalent to 12 mtpa), for an original term of 20 years from the date of first export, while providing that exports must commence no later than seven years from the date of the authorization. The authorized volumes to FTA Nations and Non-FTA Nations are not cumulative.

On October 21, 2020, DOE/FECM granted our request to extend the term in all the Calcasieu Project’s long-term export authorizations, extending the term in each Calcasieu Project export authorization through December 31, 2050 (inclusive of any make-up period).

On December 18, 2020, DOE/FECM issued a blanket order, Order No. 4641, amending certain existing export authorizations, and amended the existing long-term authorizations for the Calcasieu Project to include short-term export authority, including to export commissioning volumes.

In December 2021, we submitted an application with DOE/FECM to amend the terms of our FTA and non-FTA export authorizations for the Calcasieu Project to increase the authorized export capacity from 12.0 to 12.4 mtpa. DOE authorized the increased level of export to FTA Nations on April 22, 2022, but has not yet acted on the request to increase the authorized level of exports to Non-FTA Nations.

DOE/FECM approved on July 21, 2016, our application for exports from the Plaquemines Project to FTA Nations for 1,240 Bcf/yr of natural gas (equivalent to 24 mtpa), and originally for a term of 25 years beginning the earlier of (i) the date of first export or (ii) seven years from the date of the authorization. DOE/FECM granted us long-term authorization for export of the same 1,240 Bcf/yr of natural gas (equivalent to 24 mtpa) from the Plaquemines Project to Non-FTA Nations on October 16, 2019 for an original term of 20 years from the date of first export, while providing that exports must commence no later than seven years from the date of the authorization. The authorized volumes to FTA Nations and Non-FTA Nations are not cumulative.

On October 21, 2020, DOE/FECM granted our request to extend the term of the Plaquemines Project’s long-term export authorizations, extending the term in each Plaquemines Project export authorization through December 31, 2050 (inclusive of any make-up period).

Just as for the Calcasieu Project, the blanket order described above also amended the existing long-term authorizations for the Plaquemines Project to include short-term export authority, including to export commissioning volumes.

On March 11, 2022, we submitted an application with DOE/FECM to amend the terms of our FTA and non-FTA export authorizations for the Plaquemines Project to increase the authorized export capacity under optimal conditions from 24.0 to 27.2 mtpa. DOE authorized the increased level of export to FTA Nations on June 13, 2022, but has not yet acted on the request to increase the authorized level of exports to Non-FTA Nations, which is consistent with DOE practice of waiting to take action on the Non-FTA portion of an application until after FERC has approved the corresponding project, which occurred on February 19, 2025.

DOE/FECM approved on April 22, 2022, our application for exports from the CP2 Project to FTA Nations for a 1,446 Bcf/yr of natural gas (equivalent to 28 mtpa), for a term extending through 2050. Our request for authorization for exports from the CP2 Project to Non-FTA Nations remains pending before DOE/FECM. DOE issued a statement on December 10, 2024, stating that it cannot complete its review of non-FTA export authorizations for projects still undergoing environmental review before other federal agencies, specifically mentioning (among other projects) the FERC order on rehearing for the CP2 Project requiring supplemental environmental review.

CP3 Project and Delta Project

We have not yet filed any application with DOE/FECM for the authorization of natural gas exports from the CP3 Project or the Delta Project. We anticipate submitting the export authorization application for the CP3 Project and the Delta Project at approximately the same time as our formal FERC applications for each project.

Department of Transportation Pipeline and Hazardous Materials Safety Administration

Our projects must comply with certain safety standards set by PHMSA. 49 C.F.R. Part 193, Federal Safety Standards for Liquefied Natural Gas Facilities, which establishes minimum federal safety standards for the siting, construction, operation, and maintenance of onshore LNG facilities and the siting of marine cargo transfer systems at waterfront LNG plants. These standards also incorporate by reference the National Fire Protection Association, Standard 59A, “Standard for the Production, Storage, and Handling of Liquefied Natural Gas.” PHMSA issued a Letter of Determination, or LOD, regarding compliance with the applicable standards for each of the Calcasieu Project (including its “uprate” amendment) and the Plaquemines Project as part of the FERC process, before each project was authorized by FERC. PHMSA has also issued its LOD for the CP2 Project, as well as for the Plaquemines Project “uprate.” Once constructed and operational, each of our LNG facilities’ compliance with 49 C.F.R. Part 193 will be subject to DOT’s inspection and enforcement program.

Other Governmental Permits, Approvals and Authorizations

The construction and operation of our projects is subject to additional federal and state permits, orders, approvals, and consultations required by other federal and state agencies, including the DOE, U.S. Army Corps of Engineers, U.S. Department of Commerce, National Oceanic and Atmospheric Administration, National Marine Fisheries Services, Federal Aviation Administration, U.S. Fish and Wildlife Service, EPA, Louisiana Department of Environmental Quality, Louisiana Department of Energy and Natural Resources, and U.S. Department of Homeland Security. We currently have all material permits required for the Calcasieu Project’s and the Plaquemines Project’s respective current stage of construction and operations. Permitting for the CP2 Project remains ongoing, while permitting for the potential bolt-on expansion for the Plaquemines Project, the CP3 Project and the Delta Project is at an earlier stage.

Commodity Futures Trading Commission (CFTC)

We have entered into interest rate hedges, including interest rate swaps, in connection with the Plaquemines Credit Facilities and the Calcasieu Pass Credit Facilities, and we may enter into additional interest rate hedges and other derivatives in the future. Pursuant to authority granted by the CEA, the CFTC exercises federal oversight and regulation of the derivatives market in the United States for most types of derivatives and entities, like us, that participate in that market.

Among other CFTC requirements, the CFTC’s swaps rules impose a range of regulatory requirements on parties transacting in swaps that, among other things: (i) provide for the registration and regulation of Swap Dealers and Major Swap Participants; (ii) impose clearing and trade execution requirements for certain swaps, subject to certain exceptions; (iii) establish swaps recordkeeping and reporting regimes; and (iv) implement the CFTC’s anti-manipulation, anti-fraud, and anti-disruptive trade practice authority.

As a commercial end-user, we are subject to only limited CFTC swaps requirements. However, the application of these requirements to other market participants may affect the overall swaps market, including the costs and availability of the types of swaps we use to hedge or mitigate our commercial risks. In addition, the CFTC’s swap requirements remain subject to changes from future rule amendments, interpretive guidance and no-action relief, and the ultimate effect on our business of any changes to the rules or interpretive guidance, or of any new rules in the future, remains uncertain.

Environmental Regulation

Our projects are subject to various federal, state, and local environmental statutes and regulations intended to ensure the protection of the environment. In certain cases, these environmental laws and regulations require us to obtain permits and authorizations and engage in agency consultations prior to construction and operation of a project. Many laws and regulations restrict or prohibit the types, quantities, and concentration of substances that can be released into the environment. In addition, our LNG tankers are subject to environmental regulations, rules and conventions adopted in the jurisdictions in which they call or are flagged, including requirements to record and report their fuel consumption. Similarly, our downstream sales of LNG into, for example, the European Union, are subject to environmental-based monitoring and reporting adopted in those jurisdictions. Failure to comply with these laws and regulations may result in substantial civil and criminal fines and penalties. See Item 1A.—Risk Factors—Risks Relating to Regulation and Litigation—Existing and future environmental and similar laws and governmental regulations could result in increased compliance costs or additional operating and/or construction costs and restrictions of this Form 10-K for more information.

Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA)

Certain aspects of our projects may be subject to the Comprehensive Environmental Response, Compensation, and Liability Act, or CERCLA, which provides for the investigation, cleanup, and restoration of natural resources from releases of hazardous substances (not including “petroleum”). We may be subject to liability under CERCLA as a result of contamination at properties currently or formerly owned, leased, or operated by us or our predecessors or at third-party contaminated facilities to which we have sent waste for treatment or disposal. Liability under CERCLA can be imposed on a joint and several basis and without regard to fault or the legality of the conduct giving rise to contamination.

Clean Air Act (CAA)

Our projects are subject to the CAA and comparable state and local laws. Under the CAA, the EPA has the authority to control air pollution by issuing and enforcing regulations for entities that emit substances into the air. The EPA has promulgated regulations for major sources of air pollution and has delegated implementation of these regulations to state agencies, including the Louisiana Department of Environmental Quality and the Texas Commission on Environmental Quality. In addition to having obtained relevant air permits from the Louisiana Department of Environmental Quality prior to construction of the Calcasieu Project and the Plaquemines Project, we are subject to ongoing emissions standards, requirements, and reporting obligations under the EPA rules, as well as under Louisiana, and in the case of the CP2 Project, Texas state regulatory agencies.

Coastal Zone Management Act (CZMA)

The Coastal Zone Management Act, or CZMA, is intended to ensure the effective management, beneficial use, protection, and development of the nation’s coastal zone. Under the CZMA, participating states are required to develop management programs demonstrating how they will meet their obligations and responsibilities in managing their coastal areas. The Louisiana Department of Natural Resources, which administers the CZMA for each of our projects, issued a coastal use permit and related mitigation plan for the Calcasieu Project and an exemption for the LNG terminal and a “no direct or significant impact” (NDSI) exemption for the marine facility for the Plaquemines Project. The CP2 Project received its CZMA authorization in March 2024.

Clean Water Act (CWA) and Rivers and Harbors Act

Our projects are subject to the CWA, which regulates discharges of pollutants into the waters of the United States, as well as analogous state and local laws. Under section 401 of the CWA, a federal agency may not issue a permit for any activity that may result in any discharge into the waters of the United States unless the state where the discharge would originate either issues a water quality certification verifying compliance with existing water quality requirements or waives the certification requirement or waives this requirement. Additionally, section 404 of the CWA regulates the discharge of dredged or fill material into waters of the United States, including wetlands. Each of the Calcasieu Project, Plaquemines Project, and CP2 Project has received a water quality certification from the Louisiana Department of Environmental Quality, Water Quality Division. The Calcasieu Project and the Plaquemines Project have received CWA section 404 permits and section 10 of the Rivers and Harbors Act from the U.S. Army Corps of Engineers, or USACE, and permits from the Louisiana Department of Environmental Quality for the discharge of stormwater arising in connection with construction activities and industrial operations once construction is complete, and the discharge of wastewater generated during the operation of the facility.

Resource Conservation and Recovery Act (RCRA)

Under the Resource Conservation and Recovery Act, or RCRA, and comparable state hazardous waste laws, the EPA and authorized state agencies, including the Louisiana Department of Environmental Quality and the Texas Commission on Environmental Quality, regulate the generation, transportation, treatment, storage, and disposal of hazardous waste. If hazardous wastes are generated or stored in connection with any of our projects, we would be subject to the requirements of such laws.

Endangered Species Act, or ESA, Magnuson-Stevens Fishery Conservation and Management Act, or MSFCMA, and National Environmental Policy Act, or NEPA

Section 7 of the Endangered Species Act provides that any project authorized by any federal agency should not jeopardize the continued existence of any endangered species or threatened species, or result in the destruction or adverse modification of habitat of such species which is determined to be critical. The Magnuson-Stevens Fishery Conservation and Management Act, or MSFCMA, establishes procedures designed to identify, conserve, and enhance essential fish habitat for those species regulated under a federal fisheries management plan. During the FERC review process for each of our Projects, we engaged in consultation with the relevant federal agencies pursuant to the ESA and MSFCMA. Such consultation was completed for the Calcasieu Project, the Plaquemines Project, and the CP2 Project, but has not yet begun for the CP3 Project or the Delta Project or any potential bolt-on expansions.

The issuance of requisite permits and authorizations for our projects may be subject to environmental review under the National Environmental Protection Act, or NEPA. NEPA requires federal agencies to evaluate the environmental impact of major agency actions that may significantly affect the quality of the human environment, such as the granting of a permit or similar authorization for the development of certain projects. As part of NEPA review, federal agencies will prepare an environmental assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed environmental impact statement that may be made available for public review and comment. In May 2024, the Council on Environmental Quality, or CEQ, published its final “Phase 2” NEPA regulations, which include specific direction to account for both climate change and environmental justice effects in NEPA reviews. However, the status of these rules, as well as the NEPA review process in general, is subject to significant uncertainty. In November 2024, the majority opinion in a ruling by a panel of the U.S. Court of Appeals for the D.C. Circuit stated that the CEQ lacks authority to issue NEPA regulations. Although a subsequent majority en banc opinion by the D.C. Circuit clarified that this statement is not binding precedent, in February 2025, the District Court for North Dakota held that the CEQ lacks authority to issue NEPA regulations and vacated the CEQ’s 2024 “Phase 2” rule. In addition, executive action taken by President Trump on his first day in office with respect to energy policy and climate change, among other things, directs CEQ to propose rescinding existing NEPA regulations and issue guidance and coordinate agency level regulations implementing NEPA that expedites permitting and prioritizes energy production. On February 25, 2025, CEQ published an interim final rule, “Removal of National Environmental Policy Act Implementing Regulations,” in the Federal Register which, effective April 11, 2025, that will rescind CEQ’s existing NEPA regulations in their entirety, subject to CEQ’s consideration of public comments submitted by the effective date. The impact of these legal developments cannot be fully predicted at this time. The NEPA review process can lead to significant delays in approval of such projects and the issuance of the requisite permits. As a result of its NEPA review, a federal agency may decide to deny permits or other support for a project, or condition approvals on certain modifications or mitigation actions.

Seasonality

Seasonal weather can affect the need for our LNG sales. While we expect that a substantial amount of our LNG will be sold under long-term, post-COD SPAs, due to the commissioning activities at the Calcasieu Project and the Plaquemines Project, including the marketing, loading, and shipping of our cargos of LNG, we have already begun experiencing, and we expect to experience for our other projects as we begin commissioning activities for such projects, the effects of market volatility and fluctuation in seasonal demand for LNG in our existing markets. Additionally, excess LNG produced by our projects above the nameplate capacity that is sold to VG Commodities or otherwise can, to the extent not previously committed to third parties, be resold to third party customers at our discretion under short-, medium-, or long-term contracts, including on a forward spot basis, which would expose our revenues to such volatility and fluctuation in seasonal demand. Changes in temperature and weather may affect both power demand and power generation mix in the locations we service, including the portion of electricity provided through other sources of energy, such as hydroelectric, solar, or wind, thus affecting the need for regasified LNG. These changes can increase or decrease demand for LNG and accordingly, fluctuations in revenue during quarters of high and low demand, respectively, could have a disproportionate effect on our results of operations, especially with regard to the LNG sold into the spot market.

Competition

The global LNG and natural gas markets are highly competitive. We compete with many participants across an integrated supply chain, including independent LNG producers, commodities marketing and trading firms, national energy companies, utility companies, and major multinational energy companies, primarily over supplies of natural gas and sales of our LNG. We believe our proprietary mid-scale, factory-built liquefaction train design, project execution excellence, access to well-priced and abundant, domestically sourced natural gas, simultaneous construction and integrated operations approach, with its associated commissioning cargos and proceeds, capital strength, leadership, and mission and values-led culture position Venture Global well to compete and thrive against this diverse competitive landscape.

We are subject to market-based price competition, reflecting supply and demand market pricing dynamics, with respect to revenue associated with any sales of our commissioning cargos and sales of LNG in excess of our nameplate capacity. Due to the commissioning activities at the Calcasieu Project, including the marketing, loading and shipping of our cargos of LNG, we have already begun experiencing competition with respect to LNG sales, including the effects of changes in supply and demand due to recent market volatility. The balance between the availability of LNG and the market demand for LNG significantly affects competition and the market price for our products. This dynamic is particularly acute for cargos sold on a forward spot or short-term contracted basis, such as any commissioning and excess capacity cargos. Even after COD for our projects, we may continue to have a meaningful component of our production and sales subject to spot and short- or intermediate-term market dynamics. This may occur as a result of marketing excess capacity cargos through VG Commodities under excess capacity SPAs to the extent these cargos are not previously contracted, or as a result of marketing any portion of the nameplate capacity of our projects that is not contracted under post-COD SPAs at any time.

Our current development projects, any future projects we develop, and any expansions of our projects will compete with other domestic and international suppliers on the basis of price per contracted volume of LNG with other LNG projects throughout the world, including other LNG projects being developed by us and other LNG projects in operation and under development.

With respect to our projects, our current and potential competitors include, but are not limited to, (1) national energy companies, such as QatarEnergy, (2) major multinational energy companies, including BP, Chevron, ConocoPhillips, ExxonMobil, Shell and Total, (3) independent LNG producers, including Cheniere and Freeport LNG, (4) utility companies, such as Sempra, and (5) commodities marketing and trading firms, such as Glencore, Trafigura, and Vitol. Some of our competitors may have financial, engineering, marketing, and other resources greater than we have, and some of them are fully integrated energy companies. Importantly, many of our competitors are also our customers with whom we have short-, intermediate-, and long-term contractual relationships.

Insurance

We maintain a comprehensive insurance program to insure potential losses to Venture Global, the Calcasieu Project, and the Plaquemines Project from physical loss or damage, including due to floods and named windstorms, as well as third-party liabilities, during construction and subsequent operation. We expect to establish a similar comprehensive insurance program for the CP2 Project, with initial environmental, third party liability, and cargo policies in place, and our current development projects at the appropriate and prudent time. In addition, we expect to establish a comprehensive insurance program to insure against customary risks and losses for our LNG tankers and regasification terminal assets at the appropriate and prudent time and have already placed protection and indemnity coverage and hull and machinery insurance for our two, newbuild LNG tankers that were delivered in July 2024 and placed charterers’ liability insurance for our four chartered LNG tankers that were delivered in the second half of 2024. We may not be able to maintain adequate insurance in the future at rates that are considered reasonable. See Item 1A.—Risk Factors—Risks Relating to Our Business—We are unable to insure against all potential risks and may become subject to higher than expected insurance premiums. In addition, we retain certain risks as a result of insurance through our captive insurance of this Form 10-K.

Available Information

Our Class A common stock has been publicly traded since January 24, 2025 and is traded on the New York Stock Exchange under the symbol “VG.” Our principal executive offices are located at 1001 19th Street North, Suite 1500, Arlington, VA, 22209, and our telephone number is (202) 759-6740. Our internet address is www.ventureglobal.com. We provide public access to our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to these reports as soon as reasonably practicable after we electronically file those materials with, or furnish those materials to, the SEC under the Exchange Act. These reports may be accessed free of charge through our internet website. We make our website content available for informational purposes only. The website should not be relied upon for investment purposes and is not incorporated by reference into this Form 10-K.

We will also make available to any stockholder, without charge, copies of our annual report on Form 10-K as filed with the SEC. For copies of this, or any other filing, please contact: Venture Global, Inc., Investor Relations, 1001 19th Street North, Suite 1500, Arlington, VA, 22209 or call (202) 759-6740. The SEC maintains an internet site (www.sec.gov) that contains reports, proxy and information statements, and other information regarding issuers.